Method for inhibiting scale formation in oil wells

ABSTRACT

An illustrative method of reducing an amount of treatment water injected into a subterranean well may include providing an environmentally friendly polymer, such as a biodegradable polymer (e.g., an aspartic acid based polymer), to the subterranean well. In some cases, the aspartic acid based polymer may include one or more of a copolymer of the aspartic acid based polymer, a terpolymer of the aspartic acid based polymer, an aspartic acid based polymer derivative, an aspartic acid based polymer having an end cap, and a soluble salt of the aspartic acid based polymer. In some cases, the treatment water use may be reduced within the range of about five percent to about ninety five percent.

RELATED APPLICATION

This application claims priority to U.S. Provisional Patent ApplicationSerial. No. 61/605,036, filed Feb. 29, 2012 and entitled “METHOD FORINHIBITING SCALE FORMATION IN OIL WELLS,” which is hereby incorporatedby reference.

TECHNICAL FIELD

The present invention relates generally to controlling scale formationin hydrocarbon producing wells, and more specifically to inhibit scaleformation by controlling the formation of halite scale in hydrocarbonproducing wells.

BACKGROUND

In some cases, well bores drilled into hydrocarbon containing rockformations may allow for oil to be extracted substantially free ofimpurities. However, many hydrocarbon containing rock formations includewater having a particular mineral content (e.g., calcium, magnesium,sulfur, sodium, iron, etc.). This water may have been trapped during theformation of the rock, such as connate water, or may have been naturallyintroduced to the rock formation later, such as interstitial water, andare often referred to as brines. These brines may have a relatively highdissolved mineral content and may contain high concentrations ofdissolved salts. Brines and/or other formation waters may be foundwithin the pores of the rock formations with the hydrocarbon, withinpores of the rock formations separate from the hydrocarbons, or may befound in rock formations without hydrocarbons.

SUMMARY

During the operation of a hydrocarbon producing well, halite scale mayform from the brines present in the associated rock formations leadingto reduced production of the well and/or expensive remediationprocedures. In some cases, treatment water obtained from a low salinitysource, such as a fresh water source, may be used to control scaleformation by diluting and/or dissolving halite deposits. However, due tobrine incompatibility, calcium carbonate, barium sulfate, and/or othermineral scales may form. Also, the use of the treatment water and/ordisposal of the formation water separated from the obtained hydrocarbonmay lead to increased cost of operation of the hydrocarbon producingwell. Many common scale inhibitors are not environmentally friendly andmay contaminate nearby ground water sources, such as those used fordrinking wells. As such, an improved system and method of controllinghalite scale formation while minimizing both the amount of treatmentwater used and the environmental impact of the operation of thehydrocarbon producing well is desired.

In some cases, an illustrative method of reducing an amount of treatmentwater injected into a subterranean well may include providing anenvironmentally friendly polymer, such as a biodegradable polymer (e.g.,an aspartic acid based polymer), to the subterranean well. In somecases, the aspartic acid based polymer may include one or more of acopolymer of the aspartic acid based polymer, a terpolymer of theaspartic acid based polymer, an aspartic acid based polymer derivative,an aspartic acid based polymer having an end cap, and a soluble salt ofthe aspartic acid based polymer. In some cases, the treatment water usemay be reduced within the range of about five percent to about ninetyfive percent.

In some cases, an illustrative method for inhibiting halite scaleformation in a subterranean well may include providing treatment waterinto the subterranean well and providing an aspartic acid based polymerto the subterranean well. The illustrative method may further includeadjusting a concentration of the aspartic acid based polymer in thetreatment water. In some cases, the illustrative method may includeinjecting the treatment water into the subterranean well at a firstspecified rate and adjusting a rate of injection of the treatment waterinto the subterranean well to a second rate of injection, wherein thesecond rate of injection is less than a first rate of injection. In somecases, the scale inhibitor may be provided at a rate and/orconcentration configured to reduce or minimize the amount of freshwatersupplied to the well bore.

An illustrative system for reducing or minimizing scale formation in asubterranean well may include a water source and an aspartic acid basedpolymer. Water may be obtained from the water source and provided to thesubterranean well to at least partially inhibit scale formation withinthe well. The aspartic acid based polymer may be provided to thesubterranean well at a specified concentration in the water obtainedfrom the water source. In some cases, the illustrative system mayinclude a controller. The controller may be configured to control therate of flow of the water provided to the subterranean well and/or tocontrol the concentration of the aspartic acid based polymer in thewater provided to the subterranean well.

The preceding summary is provided to facilitate an understanding of someof the innovative features unique to the present invention and is notintended to be a full description. A full appreciation of the inventioncan be gained by taking the entire specification, claims, drawings, andabstract as a whole.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention may be more completely understood in consideration of thefollowing detailed description of various embodiments in connection withthe accompanying drawings, in which:

FIG. 1 shows an illustrative laboratory experiment for use in simulatingscale formation caused by brine of a hydrocarbon containing formation;

FIGS. 2A-2D shows illustrative experimental results obtained using thelaboratory experiment of FIG. 1 for untreated brine;

FIGS. 3A-3D shows illustrative experimental results obtained using thelaboratory experiment of FIG. 1 for brine treated with a polymer at arate of 10 ppm;

FIGS. 4A-4D shows illustrative experimental results obtained using thelaboratory experiment of FIG. 1 for brine treated with a polymer at arate of 20 ppm;

FIGS. 5A-5D show experimental results for a series of jar tests using amixture of scale inhibitors and deionized water over differentdurations;

FIG. 6 shows experimental results of a series of jar tests to determinea qualitative understanding of an amount of precipitate and or flocformed at particular dosage levels;

FIGS. 7 and 8 show experimental results from a series of experimentaljar tests for particular concentrations levels of the aspartic acidbased polymer;

FIGS. 9 and 10 show experimental results from a from a series ofexperimental jar tests for particular concentrations levels of theaspartic acid based polymer in different brine formulations;

FIGS. 11 and 12 show experimental results from a from a series ofexperimental jar test for particular concentrations levels of anaspartic acid based polymer in different brine formulations;

FIG. 13 shows experimental results for a series of jar tests comparingscale inhibition of different aspartic acid based polymers havingdifferent molecular weights;

FIG. 14 shows experimental results for a series of jar tests comparingscale inhibition properties of several aspartic acid based polymers andseveral non-aspartic acid based polymers;

FIGS. 15A and 15B show experimental results for a series of jar testscomparing scale inhibition capabilities of water, brine and a mixture ofa scale inhibitor and brine;

FIGS. 16A and 16B show experimental results for a series of jar testscomparing scale inhibition capabilities of water, brine and a mixture ofa scale inhibitor and brine;

FIG. 17 shows an illustrative system for inhibiting halite scaleformation in a hydrocarbon producing well;

FIG. 18 shows an illustrative controller of the illustrative system ofFIG. 17 for controlling treatment water usage and/or a concentrationlevel of an aspartic acid based polymer; and

FIG. 19 shows an illustrative method for inhibiting scale formation in asubterranean well and/or equipment associated with the subterraneanwell.

While the invention is amenable to various modifications and alternativeforms, specifics thereof have been shown by way of example in thedrawings and will be described in detail. It should be understood,however, that the intention is not to limit aspects of the invention tothe particular embodiments described. On the contrary, the intention isto cover all modifications, equivalents, and alternatives falling withinthe spirit and scope of the invention.

DESCRIPTION

The following description should be read with reference to the drawingswherein like reference numerals indicate like elements throughout theseveral views. The detailed description and drawings show severalembodiments which are meant to illustrative of the claimed invention.

In some cases, oilfield waters are mixed with the hydrocarbons of theoil fields. For example, in the oilfields in North Dakota, thehydrocarbons may occur in formations mixed with approximately equalamounts of brine. When the hydrocarbons (e.g., crude oil, natural gas,etc.) are captured, the brines may be separated from the hydrocarbonsand may be disposed, such as by injecting the recovered brines into deepdisposal wells. Brines and other oilfield waters may vary in mineralcomposition and/or mineral concentrations, often based on a geographicallocation. For example, the mineral content of brines in some locations,such as North Dakota, may be predominated by chlorides. In someexamples, the brines may have a high salinity and may includeapproximately 90% sodium chloride (NaCl), also called halite. The highsalinity brine may include other salts such as calcium chloride (CaCl₂)and magnesium chloride (MgCl₂). In one example, a thousand gallons(e.g., about 24 barrels) of a high salinity brine may contain over a tonof NaCl. An illustrative brine composition, including approximate ionconcentration levels, is presented below in Table 1.

TABLE 1 Illustrative ion concentrations in an illustrative high salinitybrine. Concentration Ion (mg/L) Na⁺ 109,843 Ca²⁺ 24,653 Mg²⁺ 1,740 K⁺8,265 Ba²⁺ 55 Sr²⁺ 986 Fe²⁺/Fe³⁺ 3 Cl⁻ 202,950 HCO₃ ⁻ 153“Understanding the Mechanisms of Halite Inhibition and Evaluation ofHalite Scale Inhibitor by Static and Dynamic Tests” (SPE InternationalSymposium on Oilfield Chemistry, 20-22 Apr. 2009, The Woodlands. Texas)by Tao Chen, et al., states that inhibiting halite scale formationduring oil and gas production is difficult because of the concentrationlevels of halite inhibitors. Further, laboratory tests of haliteinhibitors have been difficult to perform and/or reproduce.

Halite scale is one of many scales (e.g., carbonate scale, sulphatescale, etc.) found in the oil and gas industry due to the mineralcontent of the brines. Halite scales may form by condensation from gasgeneration, when the temperature of the brine is reduced or othersimilar reasons. For example, in Northern German gas reservoirs, haliteprecipitation was seen as the gas was recovered from the formation.Halite may precipitate in and/or near the well bore when brines arepresent in the formation. Halite scale has been shown to reduce theperformance of the wellbore, including decreasing the production rate.In some cases, halite scale may block the flow path through the pores ofthe rock formations, sometimes causing a well to be abandoned. Halitescale may also form on topside equipment, such as pipes, tubes, pumps,compressors, and the like, when the formation fluid cools and/orevaporates. In one case, halite scale formation was observed insubmersible pumps and jet pumps at a particular well site causing lostproduction during downtime required to remove the scale. In some cases,attempts have been made to control halite scale by using fresh watertreatments and/or chemical treatments. Chemical treatments, such asacidic based treatments, have provided limited benefits and/or do notuse environmentally friendly products. Fresh water treatments, whichintroduce fresh water down the well bore during production, oftenrequires a relatively large amount of treatment water to be used atregular intervals. Dilution with treatment water (e.g., fresh water,reclaimed water, formation water, etc.) may be the most common methodused today to help control halite scale formation in rock formationshaving brines with relatively high salinity.

In the production of oil and/or gas from formations that contain areasof high brine, the formation of sodium chloride salt may require the useof extremely large quantities of fresh water to dilute the brine. Thisdilution may help reduce scale formation in an attempt to prevent thepores in the formation rock, the well bore and the pump equipment frombecoming obstructed. However, fresh water in many places may be alimited resource so that it is desirable that a method be found to bothreduce freshwater usage and inhibit scale formation in a well bore. Insome cases, such as in the oil and/or gas fields of the North Sea,seawater may be used to dilute the brine in the hydrocarbon bearingformation. However, in either case, the mineral content in the freshwater (e.g., bicarbonate) or the sea water (e.g., sulphates) may causethe formation of other scales (e.g., calcium carbonate) and/or causecorrosion of equipment. An illustrative mineral content of anillustrative treatment water source is provided in Table 2, below.

TABLE 2 Illustrative ion concentrations of an illustrative treatmentwater. Concentration Ion (mg/L) Na⁺ 800 Ca²⁺ 4 Mg²⁺ 1 K⁺ 3 Ba²⁺ 0.2 Sr²⁺0.2 Fe²⁺/Fe³⁺ 0.1 Cl⁻ 220 HCO₃ ⁻ 1342

It has been found that the use of an aspartic acid based polymer, suchas the biodegradable polymer polyaspartic acid, may significantly reducetreatment water usage (e.g., fresh water, sea water, reclaimed water,formation water, reclaimed water, etc.) by reducing adherent scaleformation and/or dissolvable scale formation. In some cases, theaspartic acid based polymer may be non-toxic and/or non-hazardous. Insome cases, the aspartic acid based polymer may be stable over a widerange of temperatures. In some cases, the aspartic acid based polymermay be biodegradable and may meet the criteria of one or moreinternational standards for biodegradability (e.g., OECD 301, 302, 306,etc.). In one example, the aspartic acid based polymer may be appliedwith a concentration within the range of 5 parts per million (ppm) toabout 1000 ppm, when pumped into the well with the treatment water, andmay reduce the treatment water usage by about fifty to about ninety-fivepercent. In another example, applying an aspartic acid based polymer(e.g., polyaspartic acid, etc.) at a concentration of about 100 ppmwithin the flow of treatment water introduced into the well bore hasbeen found to allow for a significant reduction of treatment water use.

Many environmental regulations have been implemented around the world toregulate the use and/or characteristics of chemicals used in variousindustries, such as in the hydrocarbon production industry (e.g., theoil and gas industry). For example, environmental standards have beenestablished to regulate oil and/or gas production from fields in theNorth Sea region. Any chemical used within the North Sea oilfields mustmeet those standards. Similarly, in the United States, one or more setsof environmental regulations may be defined by the national and/or stategovernmental agencies. A clear understanding of the national and localstate laws is required when evaluating a chemical for use in hydrocarbonproducing wells. For example, in many areas, the toxicity of chemicalsused in the fraccing industry is coming under scrutiny of governmentagencies, environmental watchdog groups and the public at large. As thestandards are likely to become more stringent and/or more widelyadopted, a need for more environmentally friendly products is needed.

For example, the environmental laws and regulations present in the NorthSea region require the evaluation of the environmental profile ofchemicals based upon their biodegradation, bioaccumulative and/ortoxicity test results. The most recognized tests for measuringbiodegradation of chemicals are the standards developed by theOrganization for Economic Cooperation and Development (OECD). These OECDtests include methods that may be performed purely in a laboratoryenvironment, in a simulated environment, and/or in a field-based testenvironment. Biodegradation may be affected by many factors, the testsdiffer based on the environment of the intended use (e.g. a freshwaterenvironment, a sea water environment, a soil environment, an aquaticsediment environment, a sewage treatment plant environment, etc.) Thebiodegradation of products used in ocean environments are oftenevaluated using the OECD 306 test method. Table 3 below includes anoverview of the OECD biodegradation tests in relation to the intendeduse environment and a testing classification.

TABLE 3 OECD biodegradability test overview. Sewage Aquatic treatmentFresh Sea Test type Soil Sediment plant water water Ultimate 306 Ready301A-E 306 Inherent 304 A 302 A 302 B Simulation 307 B 308 B 303A

To achieve the highest biodegradation rating defined by the OECD, achemical must show biodegradation of greater than 60% over 28 days. Abioaccumulation test evaluates the partition coefficient of a chemicalbetween water and octanol and is expressed as log P_(ow). To beconsidered non-bioaccumulative, the log P_(ow) of a chemical should havea value of less than 3. However, if the molecule of the chemical has amolecular weight greater than 700, it is not expected to bioaccumulate.Various toxicity tests evaluate the EC₅₀ (e.g., paralysis, loss ofequilibrium, and/or other sub-lethal endpoints) and LC₅₀ (e.g., Death)thresholds for a particular chemical. In the North Sea region, thevarious standards specify that the EC₅₀ and LC₅₀ must be greater than 10mg/L to be considered non-toxic.

Below, Table 4 summarizes the environmental test results for aparticular aspartic acid based polymer (e.g., polyaspartate).

TABLE 4 Environmental testing results for an aspartic acid basedpolymer. Test Result Biodegredation (28 days, OECD 306) 64%Bioaccumulation (log P_(ow)) (OECD 117) <−5 Skeletonema costatum EC₅₀ 72h (mg/L) >10,000 Acartia tonsa EC₅₀ 48 h (mg/L) >9,000 Scophthalmesrnaximus juvenile LC50 96 h (mg/L) >9,000Based upon these test results, the aspartic acid based polymer would beapproved for use in the North Sea due to its favorable environmentalprofile. As such, the aspartic acid based polymer may be suitable foruse in similar applications when environmental impact is of concern.

FIG. 1 shows an illustrative laboratory experiment 100 that may be usedfor simulating halite scale formation caused by brine of a hydrocarboncontaining formation. The illustrative laboratory experiment is designedto test the effectiveness of a polymer, such as an aspartic acid basedpolymer. In some cases, the aspartic acid based polymer may include oneor more of a copolymer of the aspartic acid based polymer, a terpolymerof the aspartic acid based polymer, an aspartic acid based polymerderivative, an aspartic acid based polymer having an end cap, and asoluble salt of the aspartic acid based polymer, such as, for example,polyaspartic acid to at least inhibit halite scale formation from abrine in a heated environment (e.g., a hydrocarbon bearing formationmatrix) and/or on a heated surface (e.g. a surface of a piece ofequipment). During the experiments, a brine 110 that was not treated wasrun to simulate the down-hole environment of formation brine watercontacting a heated surface, such as equipment (e.g., a pump), the wellbore, and/or another surface (e.g., the pore of the rock formation). Thebrine 110 was formulated to simulate the brine water encountered in arock formation. For example, the experimental brine water formulationmay simulate the brine found in a natural gas and/or crude oil bearingformation, such as in North Dakota. The simulated brine 110 may containone or more dissolved minerals at various concentrations, as illustratedin Table 1 above. For example, the brine may include sodium ions (Na⁺),calcium ions (Ca²⁺), magnesium ions (Mg²⁺), sulfide ions, nitrite ions,bromide ions, nitrate ions, chloride ions, carbonate ions and/or otherions capable of forming scale deposits.

In the illustrative experiment 100 of FIG. 1, the brine 110 is pumped115 by a pump 120 from a first beaker 130 such that the brine 110 flowsover a heating element 140 of an immersion heater 150 into a secondbeaker 160. In an example, the heating element 140 may be a quartzimmersion heater to simulate a heat transfer surface found within a wellbore, such as a pore in the rock formation, the side of the well bore,or a surface of a pump or other machinery associated with the well bore.In some cases, the immersion heater 150 may be configured to provideheat within a specified temperature range (e.g., from about 110° C. toabout 250° C.). In the example shown, a display 155 may provide a visualrepresentation of the temperature of the heating element 140. In theexample shown, the heating element 140 of the immersion heater 150 wasconfigured to produce heat at 124° C.

In some cases, a specified amount of brine 110 was pumped 115 from thefirst beaker 130 to the second beaker 160 over a specified period oftime. In these cases, the brine 110 was configured to primarily flowover the surface 145 of the heating element 140 of the immersion heater150 before entering the second beaker 160. In one example, anexperimental run may pump approximately 250 ml of brine 110, over about1.5 hours, and the brine 110 was pumped at a substantially constant flowrate (e.g., 3.1 milliliter/minute.) In some cases, the flow rate may besubstantially continuous over a duration of time. In other cases, theflow rate may be variable over a duration of time. For example, and insome instances, the flow rate may be specified to be a first specifiedflow rate for a first duration and a second specified flow rate for asecond duration. In some cases, one of the specified flow rates may beabout zero. Over the course of each experimental run, a portion of thebrine 110 may evaporate. In some cases, approximately 75 milliliter (ml)was lost to evaporation.

FIGS. 2A-2D show illustrative experimental results 200 obtained usingthe laboratory experiment 100 of FIG. 1 for untreated brine, such as thebrine 110. For these tests, the experimental process outlined above inreference to FIG. 1 was used with the brine 110, without using any scaleinhibitor (e.g., no aspartic acid based polymer). In some cases, scale210 (e.g., halite, calcium carbonate, etc.) forms on the surface 145 ofthe heating element 140 of the immersion heater 150, which may includeone or more of an adherent scale 220, a soluble scale or a non-adherentscale, as shown in FIG. 2A. In some cases, scale 220 may be formed on asurface 225 of the second beaker 160, as shown in FIG. 2B. In somecases, scale 210 may be washed from the surface 145 of the heatingelement 140 by the brine pumped 115 from the first beaker 130. In suchcases, the resulting scale 210 may adhere to a surface 225 of the secondbeaker 160, or may remain as particulate matter in solution within thesecond beaker 160. In one example, the brine 110 within the secondbeaker 160, as shown in FIG. 2B, may be turbid due to either theadherent scale 220 or the particulate matter resulting from scale 210washed from the heating element 140 by the brine 110.

As discussed above, the scales 210, 220 formed may include scales of oneor more ions contained in the brine 110. In some cases, the scales 210,220 may be adherent to one or more surfaces 145, 225 of the experimentalsetup, such as the heating element 140 and/or the second beaker 160.FIGS. 2C and 2D show the second beaker 160 and the heating element 140after being rinsed of non-adherent scale and/or soluble scale. After therunoff water (e.g., brine 110) was removed from the second beaker 160,the bottom of the second beaker 160 was scratched 230 with a plastic rodto show the presence of adherent scale 220. Similarly, the heatingelement 140 was rinsed to remove soluble scale and/or non-adherent scalefrom the surface 145 of the heating element 140. After rinsing, FIG. 2Dshows the adherent scale 220 on the surface 145 of the heating element140.

In some cases, a thermometer 170 at the distal end 147 of the heatingelement 140 may be used to monitor the immediate brine temperature aseach drop formed at the end 147 of the heating element 140. The brinetemperature of each drop as it ran down the heating element 140,increased from 23° C. to about 63° C. before dropping into the secondbeaker 160. In some cases, the reduced heat transfer caused by the scale220 formed on the heating element 140 may cause the drop temperature tobe reduced (e.g., within a range from about 45° C. to about 55° C.).When the brine 110 was treated with a scale inhibitor, the temperatureof each drop may was not reduced as much as had been seen with theuntreated brine 110.

FIGS. 3A-3D show illustrative experimental results 300 obtained usingthe laboratory experiment 100 of FIG. 1 for brine 110 that was treatedwith an aspartic acid based polymer at a concentration of about 10 ppm.Similarly, FIGS. 4A-4D show illustrative experimental results 400obtained using the laboratory experiment 100 of FIG. 1 for brine 110that was treated with an aspartic acid based polymer at a concentrationof about 20 ppm. As can be seen in FIGS. 4A, 4B, 5A, and 5B, theaddition of the aspartic acid based polymer, such as polyaspartic acid,may reduce the scale 210 (e.g., adherent scale 220, non-adherent scale,and/or soluble scale) on the surface 145, 225 of the heating element 140and/or the second beaker 160. Increased concentration levels of theaspartic acid based polymer produce a reduction in both adherent scale220 on the surfaces 145, 225 exposed to the heated brine 110 in FIG. 5Aand/or a reduction in turbidity of the brine 180 in the second beaker160 as shown in FIG. 5B. After rinsing the surface 145 of the heatingelement 140 and/or the surface 225 of the second beaker 160 to removenon-adherent scales and/or soluble scales, as shown in FIGS. 4C, 4D, 5C,and 5D, the adherent scale 220 is reduced in relation to theconcentration of the aspartic acid based polymer addition (e.g.,increasing the concentration from about 10 ppm to about 20 ppm). Theadherent scale 220 of the treated brine 110 is reduced for thenon-heated surfaces (e.g., the surface 225 of the second beaker 160)when treating brine 110 with a scale inhibitor, such as an aspartic acidbased polymer.

To summarize, an illustrative method of inhibiting scale formation onsurfaces associated with a hydrocarbon containing formation may includeproviding treatment water from a water source into a well bore at aspecified flow rate and providing a scale inhibitor, such as apolyaspartic acid based polymer into the well bore with the treatmentwater, wherein the scale inhibitor is supplied at a specifiedconcentration in relation to the treatment water. In some cases, thespecified concentration of the scale inhibitor may be between about 5ppm and 1000 ppm. In some cases, the specified concentration of thescale inhibitor may be about 100 parts per million. These are justexample concentrations. The specified concentration of the scaleinhibitor may be formulated to minimize or otherwise reduce the usagerate of the treatment water and/or an amount of treatment water used. Insome cases, inhibiting scale formation includes inhibiting halite scaleformation, inhibiting calcium carbonate scale formation, or inhibitinghalite scale formation and inhibiting calcium carbonate scale formation.

The scale inhibitor may include a biodegradable polymer, such as anaspartic acid based polymer such as, for example, polysuccinimide orpolyaspartic acid, and/or one or more of a copolymer of the asparticacid based polymer, a terpolymer of the aspartic acid based polymer, anaspartic acid based polymer derivative, an aspartic acid based polymerhaving an end cap, and a soluble salt of the aspartic acid basedpolymer. In some cases, inhibiting scale formation may includeinhibiting the formation of a soluble scale and/or crystal. In somecases, one or more of the treatment water and/or the aspartic acid basedpolymer may be provided continuously. In some cases, one or more of thetreatment water and/or the aspartic acid based polymer may be providedat a variable rate. In some instances, the treatment water and theaspartic acid based polymer are provided as a single solution. In otherinstances, the treatment water and the aspartic acid based polymer maybe provided separately.

In another illustrative laboratory experiment to evaluate theeffectiveness of aspartic acid based polymers against halite scaleformation, a heated and supersaturated synthetic brine solution wasused. The synthetic brine was allowed to cool so that the mitigation ofhalite formation by the aspartic acid based polymer by measuring any thedeposited halite. The synthetic brine was prepared to include waterchemistry substantially similar to that given in Table 5 below.

TABLE 5 Simulated brine formulation. Concentration Ion (mg/L) Na⁺101,680 Ca²⁺ 20,430 Mg²⁺ 2,990 K⁺ 1,490 Ba²⁺ 20 Sr²⁺ 570 Cl⁻ 204,297HCO₃ ²⁻ 130The synthetic brine solution was stored and heated at 80° C. until thesalts were dissolved. The synthetic brine solution was placed inmultiple jars to perform jar tests of various concentrations of theaspartic acid based polymer, where the jars were heated such that thesynthetic brine remained at approximately 80° C. The aspartic acid basedpolymer (e.g., polyaspartate) was added to the individual jarscontaining the synthetic brine test solution at concentrations fromabout 0 ppm (e.g., a “blank”) to about 300 ppm (e.g., 30 ppm, 40 ppm, 50ppm, 75 ppm, 200 ppm, and 300 ppm) as a 1% solution in deionized (DI)water. The bottles were then stored at 4° C. for 24 hours andobservations made over the test period. The resulting solids observed inthe bottles were filtered through a 0.45 micron filter, washed withisopropyl alcohol (IPA) and dried to assess how much scale was presentin the “blank” relative to the solutions dosed with the variousconcentrations of the aspartic acid based polymer. The results arepresented below in Table 6.

TABLE 6 Jar test results with the simulated brine of Table 3. Polymerconcentration Observation Halite mass Decrease (ppm) (after 24 hours)(grams) (%) Blank (0) Solids 1.5127 N/A 30 Solids 1.4418  4.69% 40Solids 1.3579 10.23% 50 Solids 1.2775 15.55% 75 Floc 0.0014 99.91% 200Floc No Solids  100% 300 Floc No Solids  100%As can be seen, a dosage of the aspartic acid based polymer ofapproximately 75 ppm was effective in minimizing halite scale formationin this test. This test is further discussed in the paper entitled“Successful Deployment of a Green Multifunctional Scale Inhibitor, aCase Study From the Rockies” by Spicka et al., SPE 153952, Society ofPetroleum Engineers, 2012, which is herein incorporated by reference inits entirety, particularly for its evaluation of the ability of themultifunctional scale inhibitor to inhibit scale formation of halite andother scales.

Various other scale inhibitor chemistries, such as diethylenetriamine(DETA) phosphonates, phosphate esters and vinyl sulfonated copolymers(Vs-Co), have found use in the oilfields and have been used extensivelyover many years. These types of chemistries may be used as a comparisonwhen evaluating one or more new scale inhibitors, such as the variousaspartic acid based polymers. A laboratory test was performed to comparethe ability of an aspartic acid based polymer (e.g., polyaspartate) toinhibit barium sulfate scale (e.g., using a static bottle test) andcalcium carbonate scale (e.g., using a dynamic tube block test) usingtests common in the oilfield industry. As a result, the aspartic acidbased polymer was found to inhibit calcium carbonate scale formation andbarium sulfate scale formation at similar levels to other,non-environmentally friendly chemicals, as shown below in Table 7.

TABLE 7 Scale inhibitor comparison. Approximate effective ProductConcentration (ppm) DETA Phosphonate 2 BHMT Phosphonate 2 PhosphateEster 1 Vs-Co 5 PPCA 4 Aspartic Acid Based Polymer 4

Several field tests have been done to evaluate the effectiveness of aparticular aspartic acid based polymer (e.g., polyaspartate) inhydrocarbon producing subterranean wells having a formation matrixincluding brine (e.g., a high salinity brine). In a first test, amarginally producing well (e.g., well 1) was a rod pumped well having noproduction packer and was producing approximately 25 barrels (bbl)/dayof oil, approximately 30 thousand cubic feet (MCF)/day of gas, andapproximately 150 bbl/day of brine. To control halite formation from thebrine described in Table 1, 130 bbl/day of a treatment water (e.g., thefresh water described in Table 2) was controlled during injection tomaintain a ratio of approximately 0.8 bbl of fresh water per 1 bbl offormation water (e.g., the brine). The combination of the fresh waterand the formation water caused calcium carbonate scaling on equipmentassociated with the subterranean well, as indicated in field tests andlaboratory tests using environmental scanning electron microscopy(ESEM).

To control halite formation, while simultaneously reducing the use offresh water, an aspartic acid based polymer (e.g., polyaspartate) wasapplied to the subterranean well at a concentration of 100 ppm based ontotal water produced from the well. In some cases, the dosage of theaspartic acid based polymer may be based on the combined volume of thetreatment water (e.g., fresh water) injected into the well and volume ofthe aspartic acid based polymer in solution. In some cases, the dosageconcentration of the aspartic acid based polymer may be based on acombination of the combined treatment water volume and the total waterproduced from the well. The aspartic acid based polymer was introducedinto the system by introducing the aspartic acid based polymer into thefresh water source and then injecting the combined treatment water andthe aspartic acid based polymer to the formation of the subterraneanwell via backside treatment. Initially, the treatment water includingthe aspartic acid based polymer was injected at the same ratio of 0.8bbl treatment water to 1 bbl formation water.

During this field test, the treatment was monitored and to graduallyreduce the amount of inhibited fresh water (e.g., the combination of thetreatment water and the aspartic acid based polymer) injected into thesubterranean well until to optimize the treatment water use. During thetest, to ensure that any halite deposition that may have occurred duringthe test did not cause production impairment, a 75 bbl slug of freshwater was washed down the casing every two weeks. After stabilization ofthe treatment regimen, the inhibited fresh water treatment was reducedto 70% of the original volumes. Monitoring of the subterranean wellindicated no halite deposition and ESEM analysis of the producedformation water also indicated that calcium carbonate scale was beingmitigated when compared to an ESEM image of a filter collected beforetreatment began.

After six weeks of the reduced fresh water treatment volumes, theinjection of inhibited treatment water was reduced by a further 70% toapproximately 50% of the original volumes. During this time, no haliteformation was observed in the well, indicating that the aspartic acidbased polymer was actively inhibiting halite formation. During previousattempts to reduce the fresh water injection volumes with no scaleinhibitor present, halite scale formation and/or deposition was seen inthe subterranean well and on surfaces of equipment associated with thesubterranean well. ESEM filter analysis further indicated continuedsuccessful mitigation of calcium carbonate scale as well. After sometime and continued success of the aspartic acid based polymer treatment,the injection of inhibited treatment water was further reduced toapproximately 25% of the initial volume injected, and this program iscurrently still being applied successfully.

Over an extended duration, no scale related failures have been reportedafter implementation of the treatment program. As can be seen in Table8, there has been no change in the production of formation fluids, onlya decrease in the injection of the inhibited fresh water. This 75%reduction in fresh water treatment has resulted in significant savingsto the operator due to decreased costs in water transportation anddisposal. As a result of the successful treatment the well ownerrequested that a second well be used for a second field trial. Table 8shows a comparison of the production values for the well before thetreatment program with the aspartic acid based polymer began and afterthe treatment program had been optimized (e.g., minimization of freshwater use) based on the field test results as described above.

TABLE 8 Results of treatment program on well 1. Pre-treatment Optimizedtreatment (bbl/day) (bbl/day) Fresh water injection 138 34 Formationwater 256 241 production Oil production 25 25.5 Gas production 41 43

In the field test at the second well (well 2), the bottom holetemperature of the subterranean well was approximately 280° F., hadhigher production levels compared to well 1, and produced approximately900 bbl/day of high salinity formation water (e.g., the brine of Table9), 163 bbl/day of oil and 219 MCF/day of gas.

TABLE 9 Ion concentrations the high salinity brine of well 2.Concentration Ion (mg/L) Na⁺ 66,777 Ca²⁺ 43,834 Mg²⁺ 2,789 K⁺ 8,421 Ba²⁺56 Sr²⁺ 992 Fe²⁺/Fe³⁺ 12 Cl⁻ 230,681 HCO₃ ⁻ 0

Well 2 was initially completed with an ESP but was converted to a jetpump just before the start of the chemical program. The formation waterwas being diluted with 125 bbl/day of fresh water (e.g., the treatmentwater of Table 10) to control halite scale formation.

TABLE 10 Ion concentrations of the treatment water for well 2.Concentration Ion (mg/L) Na⁺ 450 Ca²⁺ 6 Mg²⁺ 0 K⁺ 1 Ba²⁺ 0 Sr²⁺ 0Fe²⁺/Fe³⁺ 0 Cl⁻ 72 HCO₃ ⁻ 305

Similarly to the treatment program used at well 1, aspartic acid basedpolymer was introduced into the treatment water before injection intowell 2 at a concentration of 100 ppm based upon total produced watervolume. The inhibited fresh water (e.g., the combined treatment waterand the aspartic acid based polymer) was applied through the power oilline to commingle with the formation water at the bottom of the well.Before the treatment program trial began, calcium carbonate scaleformation occurred in the well due to the high temperatures andcommingling of incompatible waters and was observed as a deposit on thejet pump when the pump was serviced. Calcium carbonate scale and calciumcarbonate scale was also detected via ESEM.

After establishing the chemical treatment and reducing the amount offresh water used to 70% of initial volumes, ESEM analysis indicated thatcalcium carbonate scale was being mitigated, along with the mitigatingany halite scale. The performance of the aspartic acid based polymerallowed for further reduction in the volume of injected treatment water,allowing the operator to satisfy the local authority's request thatfresh water consumption be reduced. The current optimized treatment atWell 2 is injecting fresh water at 50% of initial injection volumeswhile treating with the multifunctional scale inhibitor based uponproduced water volumes. Due to the lower volumes of injected water used,the pump is able to recover more formation fluids which has allowed thewell owner to increase oil and gas production (Table 11).

TABLE 11 Test results for the treatment program at well 2. Pre-treatmentOptimized treatment (bbl/day) (bbl/day) Oil production 126 163 Gasproduction 163 219

The revenue from increased production coupled with the cost savingsrelated to water transportation and disposal has resulted in over 1million dollars in additional revenue for the well owner per year. Inother field trials, the aspartic acid based polymer is beingsuccessfully used to treat seven wells with a reduction of fresh waterinjection volumes of in the range from about 25% to about 75% oforiginal volumes while maintaining mitigation of scale formation (e.g.,halite scale, calcium carbonate scale, etc. Before the treatment programbegan, local regulatory authorities had requested that the well operatorreduce the consumption of the fresh water taken from the local sourceused to treat well 2. To comply with the request, attempts to reduce thefresh water injection volumes led to halite deposition and lostproduction due to downtime. By using the aspartic acid based polymer,the well operator was able to simultaneously minimize scale formation,minimize treatment water use, and increase the productivity of the well

The experimental results presented in FIGS. 5A-16B, were performed in aseries of jar tests formulated to test the scale inhibition performancefor different concentrations of different scale inhibitors (e.g.,aspartic acid based polymers and non-aspartic acid based polymers). Forexample, a first brine, e.g. a sodium/calcium brine was created byadding 37 grams of NaCl and 7.4 grams of CaCl₂ to 100 g of water, andheating the water to between about 80° C. and 85° C. A second brine, asodium chloride based brine, was created by adding 37 g of NaCl to 100 gof water and heating the water to between about 80° C. and 85° C.

FIGS. 5A-5D show experimental results for a series of jar tests 500using a mixture of a scale inhibitor and deionized water to inhibitscale formation from a brine. The concentration of the scale inhibitor,the aspartic acid based polymer (e.g., polyaspartate) in the deionizedwater was formulated to be 10,000 ppm, to allow proper dosing of eachjar in the jar test, by weight. For example, 0.25 g would provide 100ppm in 25 grams of brine. In this series of jar tests 500, several jarscontaining 25 g of the first sodium/calcium based brine were dosed withdifferent concentrations 510 (e.g. 50 ppm, 100 ppm, 200 ppm, and 300ppm) of the aspartic acid based polymer in deionized water. The jarswere left to sit for different specified durations (e.g., 4 hours, 24hours, and 4 days.). After, the amount of scale was measured afterrinsing of any non-adherent scale. The amount of scale present in eachof the jar is shown as a percentage of scale inhibition in relation tothe blank (e.g., 0 ppm). The tests were repeated three times, as shownin FIGS. 5A-5C and the results averaged and presented in FIG. 5D. As canbe seen, even a relatively small dosage of between about 50 ppm and 100ppm of the aspartic acid based polymer in deionized water may cause a25% reduction in halite scale formation, and a significant scalereduction may be seen in concentrations between about 100 ppm and 300ppm.

FIG. 6 shows experimental results of a series of jar tests to determinea qualitative understanding of an amount of precipitate and or flocformed at particular dosage levels. In some cases, floc and/or flakesmay be formed as part of the scale inhibition process. In some cases,the morphology of the crystals may be changed by the presence of thescale inhibitor, such that crystals that may form may not be able toform scale deposits on a surface and may remain in solution. As can beseen in FIG. 6, scale formation and/or precipitate formation is moreprevalent at lower concentration levels 610 of the aspartic acid basedinhibitor. As the concentration levels 610 increase, precipitated andadherent scale formation decreases as floc formation may increase.

FIGS. 7 and 8 show experimental results from a series of experimentaljar tests for particular concentrations levels of the aspartic acidbased polymer, similar to the jar tests discussed above in reference toFIGS. 5A-5C. Here, various concentrations 720 of the aspartic acid basedscale inhibitor in deionized water were added to jars containing ameasured amount of the first sodium/calcium based brine. As can be seen,scale inhibition may decrease between 4 hours and 24 hours in dosagesless than about 500 ppm.

FIGS. 9 and 10 show experimental results from a series of experimentaljar tests for particular concentrations levels of the aspartic acidbased polymer in different brine formulations. Here, FIG. 9 shows aseries of 4 hour duration jar tests 810 performed by adding the asparticacid based polymer in deionized water in particular concentration levels820 to the first sodium/calcium based brine. FIG. 10 shows a series of 4hour duration jar tests 830 performed by adding the aspartic acid basedpolymer in deionized water in particular concentration levels 820 to thesecond sodium based brine. It is noticeable to see that the scaleformation of the second sodium based brine (e.g., 4.49 g of scale at 0ppm) is much higher than the scale formation of the first sodium/calciumbased brine (e.g., 2.3 g of scale at 0 ppm). However at higher dosagelevels, such as at 300 ppm, the aspartic acid based polymer solution hasa great effect in minimizing halite scale formation.

FIGS. 11 and 12 show experimental results from a series of experimentaljar tests 910, 1010 for particular concentrations 920 of an asparticacid based polymer in different brine formulations similar to the jartests discussed above in reference to FIGS. 5A-5C and 7 and 8. Here,various concentrations 920 of a different aspartic acid based scaleinhibitor, such as an aspartic acid based polymer having a differentmolecular weight, is combined in solution with deionized water and wereadded to jars containing a measured amount of the first sodium/calciumbased brine. As can be seen, for this aspartic acid based polymer, theability of this aspartic acid based polymer to inhibit scale formationappears to remain stable between 4 hours and 24 hours at all dosagelevels

In some cases, a series of experimental jar tests were performed toevaluate the capability of different non-aspartic acid based polymers atvarious concentrations to inhibit halite scale formation. For example,the different non-aspartic acid based polymers were compared to a waterblank to provide a percentage measure of ability of the non-asparticacid based polymers to inhibit halite scale formation. Severalnon-biodegradable scale inhibitor polymers provided by Nalco Company—anEcolab Company of Naperville, Ill. For example, Nalco 46025 is a 4400 MWpolyacrylate having a pH 3.2, Nalco 46037 is a 12000 MW terpolymer,acrylic, acrylamide, sulfonate having a pH 5.8, and Nalco 46350 is a6000 MW copolymer, acrylic and acrylamide having a pH 3.8. Anotherbiodegradable polymer, provided by Dequest AG, a Thermphos company ofVlissingen, Germany is Dequest PB11625, which is a <1000 MWcarboxymethyl inulin having a pH 7.0. In the jar tests, thesenon-aspartic acid based polymers were combined in solution withdeionized water and added by weight to achieve the desired dosageconcentration in the first sodium/calcium brine. The results of the jartests were inconclusive at best, However, a casual observation of theexperimental results showed that carboxymethyl inulin and the highestconcentration of the acrylic and acrylamide copolymer appear to havebetter ability to inhibit scale formation at higher concentration levelsthan the polyacrylate and the acrylic, acrylamide, sulfonate terpolymer.

In some cases, jar tests were performed to evaluate differences inhalite scale inhibition between the operation of the aspartic acid basedpolymers of differing molecular weights (e.g., between about 2000 andabout 15000, about 4000, about 7000, etc.). FIG. 13 shows experimentalresults for a series of jar tests comparing scale inhibition ofdifferent aspartic acid based polymers having different molecularweights Little difference was seen during these particular laboratoryexperiments. For example, the ability of a solution of a high molecularweight (e.g., about 15000) aspartic acid based polymer and deionizedwater was seen to be substantially similar to the ability of a solutionof a low molecular weight (e.g., about 2000) aspartic acid based polymerand deionized water in inhibiting halite scale formation.

FIG. 14 shows experimental results for a series of jar tests comparingscale inhibition properties of several aspartic acid based polymers andseveral non-aspartic acid based polymers 1420, such as the Nalcopolymers 46025, 46037 and 46350, and the Dequest polymer 11625 discussedabove, when added to the second sodium based brine. In the above seriesof experiments, it was noted that water had the ability to inhibithalite scale formation at least partially by diluting the brine. Assuch, in the previously discussed experiments, the addition of theadditional deionized water in the polymer solution, the scale inhibitingproperties of one or more of the tested polymers may not have beenproperly identified. Based on these results a second series of jar tests1450 were done using the highest dosage level of 1.25 g of water, forthe “blank” and the tested polymers. As shown in FIG. 14, none of thenon-aspartic acid based polymers saw as great a reduction in scaleformation as did the aspartic acid based polymers. In fact, each of thepolyacrylate, the terpolymer of acrylic, acrylamide, sulfonate, and thecopolymer of acrylic and acrylamide, each experienced a net increase ofscale formation. While the carboxymethyl inulin saw a reduction inhalite scale formation, the net reduction was significantly less thanthe reduction of halite formation for the three different aspartic acidbased polymers. Further, the molecular weight difference between each ofthe different aspartic acid based polymers 1470 did not appear to causea significant difference in the halite scale inhibition propertiesbetween the tested aspartic acid based polymers 1470.

FIGS. 15A and 15B show experimental results for a series of 20 ml jartests comparing scale inhibition capabilities of water and an asparticacid based scale inhibitor to a “blank” over a duration of 4 hours inthe aforementioned second sodium based brine solution. As before, aseries of jars are prepared using different concentrations 1510 of water1520, an aspartic acid based polymer 1530 and a series of “blank” jarshaving an addition of the same second sodium chloride based brine 1540.Similarly, FIGS. 16A and 16B show experimental results for a series of20 ml jar tests comparing scale inhibition capabilities of water and anaspartic acid based scale inhibitor to a “blank” over a duration of 24hours in the aforementioned second sodium based brine solution. Asbefore, a series of jars are prepared using different concentrations1610 of water 1620, an aspartic acid based polymer 1630 and a series of“blank” jars having an addition of the same second sodium chloride basedbrine 1640. As can be seen, both the water additions 1520, 1620 and theaspartic acid based polymer additions 1530, 1630, appear to provide areduction in halite scale formation, particularly at concentrationlevels above about 300 ppm. To avoid dilution of the second sodium basedbrine solution during the aspartic acid based polymer additions 1530,1630, the aspartic acid based polymer is dissolved in the same secondsodium chloride based brine solution. FIGS. 15B and 16B provide agraphical representation of the experimental results shown in the tablesof FIGS. 15A and 16A.

FIG. 17 shows an illustrative system 1700 for minimizing scale formationin a subterranean well 1710. The illustrative system 1700 may includethe subterranean well 1710 including a well bore 1715 for accessing ahydrocarbon (e.g., oil, natural gas, etc.) containing formation matrix1720, wherein the desired hydrocarbons 1725 may be found within theformation matrix along with brine 1727. In some cases, the brine may bea high salinity brine, such as the brines described above in Tables 1,5, and 9. The subterranean well 1710 may include equipment associatedwith the operation of the hydrocarbon producing well, such as the pumps1717 and 1719, and tubing and/or pipes 1718 for providing treatmentwater into the formation matrix 1720 and/or removing a mixture ofhydrocarbons 1725 and brine 1727 (e.g., the formation fluid 1729) fromthe formation matrix to the surface 1730 for processing (e.g.,separation of the hydrocarbon(s), such as oil and/or natural gas fromthe brine). As discussed above, the mineral content of the brine 1727may cause scale formation within the formation matrix (e.g., withinpores) and/or on equipment associated with the operation of thesubterranean well 1710, such as the down hole pump 1717, the surfacepump 1719, tubing and/or pipes 1718, 1721 in contact with the formationfluid (e.g., the mixture and/or emulsion of the hydrocarbons 1725 andthe brine 1727, the hydrocarbons 1725 or the brine 1727).

To prevent scale formation within the formation matrix 1720 and/or theequipment associated with the operation of the subterranean well (e.g.the pumps 1717,1718, and/or the tubing and or pipes 1718, 1721, etc.)treatment water may be provided to the formation matrix 1720 via thetubing and/or pipes 1718 within the well bore 1715. One or more watersources may provide water to be used as the treatment water 1741 for thesubterranean well 1710. For example, a water source may include a waterholding tank 1740 that may receive water from one or more differentwater sources, such as a fresh water source including a surface watersource 1742 (e.g., a lake, a river, etc.), a well 1744 for accessingwater within an aquifer 1747, and the like. For example, the system 1700may include a pump 1743 for pumping water from the surface water source1742 to the water holding tank 1740 to be used as the treatment water1741. Similarly, the system 1700 may include a pump 1745 for pumpingwater from the well 1744 to the water holding tank 1740 to be used asthe treatment water 1741. In some cases, the water sources may include aholding tank 1747 for holding treatment water 1741 obtained from one ormore non-fresh water sources, such as a source for formation fluid water(e.g., the brine 1727), a source for reclaimed water (e.g., a wastewater treatment facility), a source for production water (e.g., theproduced water 1748 separated from the hydrocarbons 1749 from theformation fluid 1729) or the like.

The system 1700 may further include a holding tank 1750, or otherstorage container, for holding a quantity of the aspartic acid basedpolymer 1755. In some cases, a pump 1751 may be used to pump theaspartic acid based polymer 1755 to a location to be added to thetreatment water, and may be controlled such that a desired concentrationis achieved. In some cases, the aspartic acid based polymer may bestored in solution, and/or in a solid form. As discussed above, theaspartic acid based polymer 1755 may include one or more of a copolymerof the aspartic acid based polymer (e.g., glutamic acid, succinic acid,malic acid, maleiamic acid, tartaric acid, aconitic acid, sorbital,etc.), a terpolymer of the aspartic acid based polymer (e.g., glutamicacid, succinic acid, malic acid, maleiamic acid, tartaric acid, aconiticacid, sorbital, etc.), an aspartic acid based polymer derivative (e.g.,ethanolamine, taurine, aminopropylquaternary amine and laurlyamine,etc.), an aspartic acid based polymer having an end cap (e.g., adipicacid, citric acid, traurine, benzoic acid, fouric acid, stearic acid,glyphosate, terephthalic acid, trans cinammic acid, etc.), and a solublesalt of the aspartic acid based polymer (e.g., alkali metal and alkaliearth metal salts such as sodium, potassium, lithium, ammonium, calcium,barium, etc.). In some cases, the aspartic acid based polymer mayinclude one or more grafts (e.g., acrylic acid, methacrylic acid, vinylacetate, vinyl sulfonic acid, carbohydrates, polysaccharides, etc.). Forexample, the aspartic acid based polymer may be polysuccinimide and/or aderivative of polysuccinimide. In some cases, the aspartic acid basedpolymer may be made using at least one dibasic acid. For example, thedibasic acid may be at least one of, but not limited to, L-asparticacid, maleic anhydride, glutamic acid, gluataric acid, adipic acid,succinic acid, tartaric acid, malic acid, maliemic acid, fumaric acid,and the like. In some cases, the aspartic acid based polymer may includeone or more soluble salts of the aspartic acid based polymer, such as apolyaspartic acid sodium salt.

As discussed above, both the treatment water 1741 and the aspartic acidbased polymer 1755 may be used for inhibiting scale formation within thesubterranean well 1710 and/or equipment 1717, 1718, 1719, and 1721associated with the subterranean well 1710. For example, treatment water1741 may be provided to the subterranean well 1710 to at least partiallyinhibit scale formation within the subterranean well 1710 and/or on asurface of the equipment 1717, 1718, 1719, and 1721 associated with thesubterranean well 1710. Similarly, the aspartic acid based polymer 1755may be used to at least partially inhibit scale formation within thesubterranean well 1710 and/or on a surface of the equipment 1717, 1718,1719, and 1721 associated with the subterranean well 1710. The asparticacid based polymer 1755 may be provided to the subterranean well 1710 ata specified concentration in the treatment water 1741 obtained from theone or more water sources 1742, 1743, 1747, 1748.

A controller 1760 may be configured for controlling at least a portionof the operation of the subterranean well 1710. For example, thecontroller 1760 may be configured to process instructions stored in anon-transitory computer readable medium for providing the treatmentwater 1741 to the subterranean well 1710 at a specified rate using thepump 1765. The controller 1760 may also be configured to provide theaspartic acid based polymer 1755 to the subterranean well at a specifiedconcentration, such as a specified concentration within the treatmentwater 1741 and/or a specified concentration corresponding to an amountof water produced from the subterranean well 1710, such as aconcentration corresponding to an amount of the produced water 1748produced from the subterranean well. In some cases, the controller 1760may be configured to minimize, or otherwise reduce, an amount of waterused from the water source by adjusting the rate of flow of the waterprovided to the subterranean well and/or the concentration of theaspartic acid based polymer.

The system 1700 may include one or more sensors 1790 for analyzing thechemistry of the different waters, such as the treatment water 1741and/or the produced water 1748, and/or the chemistry of the formationfluid 1729, such as to monitor one or more ion concentration levels. Forexample, the controller 1760 may be configured to control theconcentration and/or flow rate of the aspartic acid based polymer 1755and/or the flow rate of the treatment water 1741 to ensure properoperation of the subterranean well 1710 and/or to ensure properinhibition of scale formation.

In some cases, the controller 1760 may include a user interface 1770, ormay be associated with a user interface 1770. For example, the userinterface 1770 may be used to provide information about the operation ofthe subterranean well 1710 to a user, including information about scaleformation, water use and/or alerts and/or alarms associated with faultsand/or other error conditions of the system 1700. In some cases, thecontroller 1760 may be configured to receive information from a user viathe user interface 1770, such as information about a desired flow ratefor the treatment water 1741, a desired concentration of the asparticacid based polymer 1755 and/or information about the mineral content ofthe treatment water 1741, the produced water 1748 and/or the formationfluid 1729. In some cases, the controller 1760 may include a wiredand/or wireless connection to a network 1787, such as a local areanetwork, a wide area network, the internet, a cellular network, and thelike. The controller 1760 may be configured to exchange information withone or more device at a remote monitoring site 1780, such as a mobiledevice 1782 (e.g., a cell phone, a tablet, etc.) and/or a computer 1784.For example, the controller 1760 may be configured to communicateoperational information, such as water use rates, aspartic acid basedpolymer information, water chemistry information, hydrocarbon productionrates, and the like. Similarly, the controller 1760 may be configured toreceive one or more commands and/or operational set points from theremote monitoring site 1780 that may be used to modify and/or change theoperation of the controller 1760, such as by providing a new target ratefor treatment water usage, and/or a new concentration level for theaspartic acid based polymer.

FIG. 18 is a schematic view of an illustrative controller 1760 of FIG.17. In some instances, controller 1760 may include one or more sensors1815, and/or one or more terminals 1855 to connect to a sensor externalto the controller 1760, such as the sensors 1790 of FIG. 17, but this isnot required. In the illustrative embodiment of FIG. 18, the controller1760 includes a processor (e.g. microprocessor, microcontroller, etc.)1810, an optional sensor 1815, an optional user interface 1820, and amemory 1830. The processor 1810 may be coupled to the sensor 1815, thememory 1830, the user interface 1820, and/or the I/O block 1850.

In some cases, the input/output block (I/O block) 1850 may be forreceiving one or more signals and/or for providing one or more signals.In one example, the I/O block 1850 may be used to communicate with oneor more system components, such as the pumps 1717, 1719, 1743, 1745, and1751 and/or one or more sensors 1790 of the illustrative system 1700,sometimes via a wired interface. In some cases, the I/O block 1850 maybe used to communicate with another controller at another subterraneanwell and/or a supervisory controller configured to monitor and/orcontrol the operation of two or more subterranean wells, sometime via awired and/or wireless interface.

The I/O block 1850 may include one or more terminals 1855 (e.g., inputterminals, output terminals, universal terminals, etc.) configured toreceive control wires from one or more pumps 1717, 1719, 1743, 1745, and1751, other controllers, and/or sensors 1790. In some cases, theassignment of the terminals 1855 may be programmable, for example aterminal may be configured either as an input or an output, and/or thefunctionality of a particular terminal may be programmed. In oneexample, each of the terminals 1855 may be assigned to one or more ofthe system components and/or building controllers according to theparticular installation, and the functionality of each terminal 1855 maydepend on a characteristic of the connected devices. For example, one ofthe terminals 1855 may be configured as an output, such as when the wireterminal is used to provide a command to a pump, and another one of thewire terminals may be configured as an input when the wire terminal isto be used to receive a sensor signal from a sensor such as a sensor forsensing water chemistry (e.g., sensing an ion concentration, sensing apH, etc.). In other cases, the assignment of the terminals 1855, or someof the terminals 1855, may be fixed.

The processor 1810 of the illustrative controller 1760 may operate byprocessing control commands received from a supervisory controllerand/or command retrieved from the memory 1830, which may control or atleast partially controls one or more system components the illustrativesystem 1700 via the controller 1760. The processor 1810 may, forexample, receive specified flow rates and/or concentration levels forthe aspartic acid based polymer, and/or concentration levels for amonitored ion concentration in the formation water and/or the producedwater (e.g., a calcium ion concentration, and the like from asupervisory controller, from the user interface, and/or from memory, andmay control an appropriate system component based on the receivedinformation.

In the illustrative embodiment of FIG. 18, the user interface 1820 ofthe controller 1760, when provided, may be any suitable user interfacethat permits controller 1760 to display and/or solicit information, aswell as accept one or more user interactions. For example, the userinterface 1820 may permit a user to enter data such as information abouta desired flow rate and/or concentration level, and the like. In somecases, the user interface 1820 may include a display and a distinctkeypad. A display may be any suitable display. In some instances, adisplay may include or may be a liquid crystal display (LCD), and insome cases a fixed segment display or a dot matrix LCD display. Ifdesired, user interface 1820 may be a touch screen LCD panel thatfunctions as both display and keypad.

The memory 1830 of the illustrative controller 1760 may be incommunication with the processor 1810. The memory 1830 may be used tostore any desired information, such as the aforementioned desired ionconcentration levels, the specified concentration of the aspartic acidbased polymer, and/or the desired flow rate for the treatment water. Thememory may also store one or more algorithms that may be implemented bycontroller 1760. In some cases, the processor 1810 may operating inaccordance with an algorithm that is suitable for controlling theparticular system components of the illustrative system 1700 that areconnected to the controller 1760 in the particular installation at hand.In some cases, instructions may be stored in the memory 1830 that mayallow the processor 1810 to control the treatment water flow and/or theaspartic acid based polymer concentration corresponding to a change inone or more other parameters, such as a change in the rate ofproduction, a change in ion concentration the produced water 1748 and/orthe formation fluid 1729, a change in the composition of the treatmentwater, and the like. In some cases, the memory 1830 may be configured tostore instructions for implementing a method of reducing the usage rateof a treatment water and/or for controlling and/or inhibiting scaleformation within the subterranean well 1710 and/or on a surface ofequipment associated with the operation of the subterranean well 1710,as discussed below.

In some cases, the memory 1830 may be used to store one or more datastructures 435 containing information about a configuration of theillustrative system 1700. For example, a data structure 1835 may be usedto store information about an association between two or more of aparticular treatment water flow rate, a concentration level form theaspartic acid based polymer, an ion concentration of one or more ions inthe treatment water, the formation fluid and/or the produced water, ahydrocarbon production rate, and/or other operational information aboutthe operation of the subterranean well. In some cases, the datastructure 1835 may include information to issue a command to and/orrequest information from another controller and/or a user. The memory1830 may be any suitable type of storage device including, but notlimited to, RAM, ROM, EPROM, flash memory, a hard drive, and/or thelike. In some cases, processor 1810 may store information within memory1830, and may subsequently retrieve the stored information. For example,the memory 1830 may be used to store trend information about water usagerates, aspartic acid based concentration levels and/or usage rates,hydrocarbon production rates, water disposal rates, ion concentrationlevels, and the like.

In some cases, and as illustrated in FIG. 4, controller 1760 may includea data port 1840. The data port 1840 may be a wireless port such as aBluetooth™ port or any other wireless protocol. In other cases, the dataport 1840 may be a wired port such as a serial port, a parallel port, aCATS port, a USB (universal serial bus) port, and/or the like. In someinstances, the data port 1840 may be a USB port and may be used todownload and/or upload information from a USB flash drive or some otherdata source. Other remote devices may also be employed, as desired.

The data port 1840 may be configured to communicate with processor 1810and may, if desired, be used to upload information to the processor 1810and/or download information from the processor 1810. Information thatcan be uploaded and/or downloaded may include, for example,configuration information, rate information, concentration information,and the like. In some instances, the data port 1840 may be used toupload a previously-created controller configuration into the processor1810, thereby hastening the configuration process. For example, one ormore subterranean wells may include water chemistry and/or brinechemistry similar to a different well and a different location. In somecases, the data port 1840 may be used to download a controllerconfiguration that has been created using the controller 1760, so thatthe controller configuration may be transferred to other similarsubterranean well system controllers, hastening their configurationprocess. In some cases, the data port 1840 may be used to download datastored within the memory 1830 for analysis. For example, data port 1840may be used to download a trend log, a fault and/or alert log or partsthereof to a remote device such as a USB memory stick (also sometimesreferred to as a thumb drive or jump drive), personal computer, laptop,iPAD® or other tablet computer, PDA, smart phone, or other remotedevice, as desired. In some cases, the data may be convertible to an MSEXCEL®, MS WORD®, text, XNL, and/or Adobe PDF® file, but this iscertainly not required.

In some cases, a method for reducing an amount of water injected into asubterranean well may include providing an aspartic acid based polymerto the subterranean well, and instructions for performing the method maybe at least partially stored in the memory 1830 of the controller. Insome cases, the aspartic acid based polymer may include one or more of acopolymer of the aspartic acid based polymer, a terpolymer of theaspartic acid based polymer, an aspartic acid based polymer derivative,an aspartic acid based polymer having an end cap, and a soluble salt ofthe aspartic acid based polymer. For example, the aspartic acid basedpolymer may be polysuccinimide and/or a derivative of polysuccinimide.In some cases, the aspartic acid based polymer may be made using atleast one dibasic acid. For example, the dibasic acid may be at leastone of L-aspartic acid, maleic anhydride, and/or fumaric acid. In somecases, the aspartic acid based polymer may include one or more solublesalts of the aspartic acid based polymer, such as a polyaspartic acidsodium salt.

In some cases, providing an aspartic acid based polymer to thesubterranean well may include providing the aspartic acid based polymerat a specified concentration in a fluid, where the specifiedconcentration of the aspartic acid based polymer may be provided withina range from about 1 ppm to about 1000 ppm. In an illustrative example,the concentration of the aspartic acid based polymer may include aconcentration of polyaspartic acid and/or a polyaspartic acid salt at aconcentration within a range between about 1 part per million (ppm) toabout 1000 ppm.

In some cases, the method of reducing an amount of water injected intothe subterranean well may include inhibiting the crystallization and/orprecipitation of sodium chloride (e.g., halite). For example, the waterinjected into the subterranean well, the aspartic acid based polymerprovided to the subterranean well, or a combination of both the waterinjected into the subterranean well and the aspartic acid based polymerprovided to the subterranean well may inhibit crystallization and/orprecipitation of sodium chloride and/or one or more other crystalsand/or scale forming substances, such as calcium chloride and/or bariumsulfate. In some cases, the method of reducing an amount of waterinjected into the subterranean well may include injecting a combinationof the aspartic acid based polymer and treatment water from at least onewater source, wherein the treatment water may be obtained from one ormore of a surface water source (e.g., a river, a lake, a pond, etc.), awell water source, a reclaimed water source, a waste water source, aproduction water source and/or a fracturing fluid source. In some cases,the method of reducing an amount of water injected into the subterraneanwell may include reducing an amount of treatment water injected into thewell by about 5 percent to about 95 percent. In some cases, an amount oftreatment water obtained from a fresh water source (e.g., a river, alake, other surface water sources, a fresh water well, etc.) may bereduced using an amount of water obtained from another source, such as areclaimed water source, a waste water source, a production water sourceand/or a fracturing fluid source, use of the aspartic acid based polymerand/or a combination of water obtained from another source and theaspartic acid based polymer. For example, water may be obtained byreclaiming water from a water treatment facility, from water separatedfrom the formation fluid containing a mixture of a hydrocarbon and/or abrine, and the like.

In another example, as shown in FIG. 19, a method for inhibiting scaleformation in a subterranean well and/or equipment associated with thesubterranean well The method 1900 may, at 1910, begin by providingtreatment water into the subterranean well. For example, providingtreatment water into the subterranean well may include injecting thetreatment water into the subterranean well at a first specified rateand/or adjusting a rate of injection of the treatment water into thesubterranean well to a second rate of injection, wherein the second rateof injection is less than a first rate of injection. At 1920, anaspartic acid based polymer may be provided to the subterranean well. Insome cases, the aspartic acid based polymer is provided to thesubterranean well with the treatment water at a concentration between 1part per million (ppm) and 1000 ppm. For example, the aspartic acidbased polymer may be provided to the subterranean well at a rate thatresults in a specified concentration of the aspartic acid based polymerin the treatment water between about 25 parts per million (ppm) and 500ppm. In some cases, the method for inhibiting scale formation in thesubterranean well and/or equipment associated with the subterranean wellmay include adjusting a concentration of the aspartic acid based polymerin the treatment water.

The method of FIG. 19 may further include inhibiting sodium chloridescale and/or inhibiting one or more other scale formation (e.g., acalcium carbonate scale formation, a barium sulfate scale formation, andthe like) within a formation matrix associated with the subterraneanwell and/or on equipment associated with the subterranean well using theaspartic acid based polymer. In some cases, the aspartic acid basedpolymer may include one or more of a copolymer of the aspartic acidbased polymer, a terpolymer of the aspartic acid based polymer, anaspartic acid based polymer derivative, an aspartic acid based polymerhaving an end cap, and a soluble salt of the aspartic acid basedpolymer. For example, the aspartic acid based polymer may bepolysuccinimide and/or a derivative of polysuccinimide. In some cases,the aspartic acid based polymer may be made using at least one dibasicacid. For example, the dibasic acid may be at least one of, but notlimited to, L-aspartic acid, maleic anhydride, gluataric acid, adipicacid, succinic acid, tartaric acid, malic acid, maliemic acid, fumaricacid, and the like. In some cases, the aspartic acid based polymer mayinclude one or more soluble salts of the aspartic acid based polymer,such as a polyaspartic acid sodium salt. As discussed above,instructions for performing the method 1900 of FIG. 19 may be at leastpartially stored in the memory 1830 for use by the processor 1810 of thecontroller 1760.

Having thus described several illustrative embodiments of the presentdisclosure, those of skill in the art will readily appreciate that yetother embodiments may be made and used within the scope of the claimshereto attached. Numerous advantages of the disclosure covered by thisdocument have been set forth in the foregoing description. It will beunderstood, however, that this disclosure is, in many respect, onlyillustrative. Changes may be made in details, particularly in matters ofshape, size, and arrangement of parts without exceeding the scope of thedisclosure. The disclosure's scope is, of course, defined in thelanguage in which the appended claims are expressed.

What is claimed is:
 1. A method for reducing an amount of water injectedinto a subterranean well comprising providing an aspartic acid basedpolymer to the subterranean well.
 2. The method of claim 1, wherein theaspartic acid based polymer includes one or more of a copolymer of theaspartic acid based polymer, a terpolymer of the aspartic acid basedpolymer, an aspartic acid based polymer derivative, an aspartic acidbased polymer having an end cap, and a soluble salt of the aspartic acidbased polymer.
 3. The method of claim 2, wherein the aspartic acid basedpolymer is polysuccinimide and/or a derivative of polysuccinimide. 4.The method of claim 2, wherein the aspartic acid based polymer is madefrom at least one dibasic acid.
 5. The method of claim 4, wherein the atleast one dibasic acid is at least one of L-aspartic acid, maleicanhydride, fumaric acid, glutamic acid, gluataric acid, adipic acid,succinic acid, tartaric acid, malic acid, and/or maliemic acid.
 6. Themethod of claim 1, wherein the aspartic acid based polymer is anpolyaspartic acid sodium salt.
 7. The method of claim 1, whereinproviding the aspartic acid based polymer to the subterranean wellfurther comprises providing the aspartic acid based polymer at aspecified concentration in a fluid.
 8. The method of claim 7, whereinthe specified concentration of the aspartic acid based polymer is withina range from about 1 part per million (ppm) to about 10000 ppm.
 9. Themethod of claim 8, wherein the specified concentration of the asparticacid based polymer includes a concentration of polyaspartic acid and/ora polyaspartic acid salt at within a range between about 1 part permillion (ppm) to about 1000 ppm.
 10. The method of claim 1, furthercomprising inhibiting crystallization and/or precipitation of sodiumchloride.
 11. The method of claim 1, further comprising injecting acombination of the aspartic acid based polymer and treatment water fromat least one water source.
 12. The method of claim 11, wherein the atleast one water source includes one or more of a surface water source, awell water source, a reclaimed water source, a waste water source, aproduction water source and/or a fracturing fluid source.
 13. The methodof claim 11, further comprising reducing an amount of treatment waterinjected into the subterranean well by about 5 percent to about 95percent.
 14. A method for inhibiting scale formation in a subterraneanwell, the method comprising: providing treatment water into thesubterranean well; and providing an aspartic acid based polymer to thesubterranean well.
 15. The method of claim 14, further comprisingadjusting a concentration of the aspartic acid based polymer in thetreatment water.
 16. The method of claim 14, comprising: injecting thetreatment water into the subterranean well at a first specified rate;and adjusting a rate of injection of the treatment water into thesubterranean well to a second rate of injection, wherein the second rateof injection is less than a first rate of injection.
 17. The method ofclaim 14, wherein the aspartic acid based polymer is provided to thesubterranean well with the treatment water at a concentration between 1part per million (ppm) and 1000 ppm.
 18. The method of claim 14, whereinthe aspartic acid based polymer is provided into the subterranean wellat a rate that results in a specified concentration of the aspartic acidbased polymer in the treatment water between about 25 parts per million(ppm) and 500 ppm.
 19. The method of claim 14, further comprisinginhibiting sodium chloride scale within a formation matrix associatedwith the subterranean well and/or on equipment associated with thesubterranean well.
 20. The method of claim 18, comprising inhibiting atleast one of a calcium carbonate scale formation and a barium sulfatescale formation.
 21. The method of claim 14, wherein the aspartic acidbased polymer is polysuccinimide and/or a derivative of polysuccinimide.22. A system for minimizing scale formation in a subterranean wellcomprising: a water source, wherein water is obtained from the watersource and provided to the subterranean well to at least partiallyinhibit scale formation within the subterranean well; and an asparticacid based polymer, wherein the aspartic acid based polymer is providedto the subterranean well at a specified concentration in the waterobtained from the water source.
 23. The system of claim 22, furthercomprising a controller, the controller for controlling a rate of flowof the water provided to the subterranean well and/or for controllingthe a concentration of the aspartic acid based polymer in the waterprovided to the subterranean well.
 24. The system of claim 23, whereinthe controller is configured to minimize an amount of water used fromthe water source by adjusting the rate of flow of the water provided tothe subterranean well and/or the concentration of the aspartic acidbased polymer.
 25. The system of claim 22, further comprising a pumpconfigured to obtain a formation fluid from the subterranean well. 26.The system of claim 25, wherein a combination of the water and theaspartic acid based polymer minimizes scale formation on surfacesassociated with the pump and/or within a formation matrix associatedwith the subterranean well.